Whilst assessing hydrocarbon bearing formations and reservoirs, it is important to acquire knowledge of formation and formation fluid properties which influence the production or yield from the drilled formation. Indeed, as the hydrocarbon bearing formation is produced and formation fluid is extracted to a surface location, a portion of the hydrocarbon initially present in the formation pores remains in the formation, limiting thereby the amount of hydrocarbon that may be recovered from the formation, or the total production capacity. In particular, this portion of hydrocarbon may be quantified using an important formation property or parameter, the Residual Oil Saturation, sometimes referred to as ROS or SOR.
Various techniques are known to decrease the residual oil saturation in hydrocarbon bearing formations and reservoirs, and thereby increase the total production capacity. These techniques, sometimes referred to as Enhanced Oil Recovery (EOR) techniques, include but are not limited to the injection of fluid that may contain surfactants, solvents, stimulants, hydrocarbons, or other fluid(s) that changes the mobility, wetting phase, and/or saturation of the reservoir fluid. The ROS measured after various EOR schemes can also be used to evaluate the improvement of the oil recovery factor. The measured ROS may be useful to determine if a particular EOR scheme provides sufficient improvement in oil recovery that would overcome the cost of its associated EOR scheme.
Core analysis may be useful to determine the ROS in a hydrocarbon reservoir. This technique, sometimes referred to as Special Core AnaLysis (SCAL), involves capturing cores at selected locations in a well drilled in the formation, and bringing the cores to a surface laboratory. At the surface laboratory, a formation fluid is first reintroduced in the cores. Then, the formation fluid is flushed with a substitution fluid (e.g. reservoir water, reservoir gas, etc. . . . ) and the ROS is measured. The ROS measured for the plurality of cores may further be correlated to well logging properties measured at the capture locations of the cores. An ROS may thereby be extrapolated along the entire producing formation using the well logging properties. However, there may in some cases be drawbacks to ROS determination from core analysis. First, core analysis may only be representative of what is happening in the rock matrix at a relatively small scale (e.g. the size of the core), and may not be representative of the formation at a larger scale. Second, capturing the core(s) may be operationally complex and expensive, and may not be reliable in all formation types, for example in highly fractured formations. Thus, it may be advantageous in some cases to measure the ROS in situ.
Well injection techniques may also be useful to determine the ROS in a hydrocarbon reservoir. A known technique, sometimes referred to as Nuclear Magnetic Resonance (NMR) log-inject-log method, involves substituting the wellbore fluid with Manganese Chloride (MnCl2) doped water, measuring a first NMR log over the length of the well to estimate an initial or pristine oil saturation in the formation surrounding the wellbore, reaming a portion of the well for facilitating the injection of MnCl2 doped water into the formation surrounding the wellbore, and measuring a second NMR log over the length of the well to estimate the Residual Oil Saturation after the formation water has been displaced by the MnCl2 doped water. However, as is apparent to the persons skilled in the art, this method involves complex logistics and expensive rig time. Thus, it may be advantageous in some cases to provide a method for estimating the ROS that involves injecting fluid through a localized portion of the well.